1.2 Currently Operating & Near Future Offshore CCS Projects

The remainder of this Chapter focuses on those regions where sub-seafloor geological storage of CO2 is currently occurring, or is planned for the near future. This includes Japan, South East Asia, Oceania and Western Europe. Of these regions, South East Asia, Oceania and Western Europe were identified above as key regions where offshore storage could play a significant role in CCS due to the dominance of offshore with respect to onshore storage capacity.

1.2.1 Japan

An assessment of potential geological storage sites in the Asia-Pacific Economic Cooperation (APEC) region excluded the possibility of geological storage in Japan due to the lack of storage capacity in hydrocarbon reservoirs and minimal sedimentary basins that would meet the criteria for geological storage of CO2 (Bachu, 2003). Indeed, in the assessment of Dooley et al. (2005), Japans technical storage capacity in saline aquifers is rated at 0 GtCO2. These evaluations reflect concerns regarding the security of CO2 storage in tectonically active areas such as the Pacific Rim due to the complexity of geological structures and the risk of reactivating faults during injection of CO2 (e.g. Bradshaw & Dance, 2005). Nevertheless, there are several petroleum provinces that are tectonically active and have stored substantial volumes of hydrocarbons (e.g. California and parts of South East Asia) and such locations should not be automatically dismissed as unsuitable CO2 storage locations (Bradshaw & Dance, 2005).

While perhaps not providing the optimum storage sites at the high level of the APEC region, at the national level Japan considers CCS to be one the key technologies that could be employed to reduce net emissions post-2010, and is actively pursuing the geological storage of CO2 in deep saline aquifers. Offshore storage sites also appear to be preferred to onshore sites due to both adequate storage capacity and a greater margin of safety with respect to human health in the event of a possible leakage. To the author’s knowledge no commercial scale projects have been announced as yet. Nevertheless, Japan is included in the discussions here as it is one of few countries that have conducted detailed work on the regional potential (technical and economic) CO2 storage capacity and has a clearly stated mission to implement offshore storage in the near future. The dynamic research and development program on CO2 sequestration in Japan is coordinated by the Research Institute of Innovative Technology for the Earth (RITE).

An early assessment of Japans geological storage capacity, carried out by the Engineering Advancement Association of Japan (ENAA), identified 60 potential sites, including oil and gas fields and aquifers, with an estimated capacity of ~91.5 GtCO2 (Tanaka et al., 1995). 29 of these sites, with a capacity in excess of 72 GtCO2, were located offshore (Tanaka et al., 1995). Encouraged by the large potential storage capacity, RITE and ENAA undertook a 5 year joint R&D project (2000-2005) entitled ‘Underground Storage of Carbon Dioxide’ (Kaya et al., 2001). One of the main objectives of this project was to identify candidate storage sites for large-scale demonstration projects followed by commercial implementation in the near future, where site selection would be based on both safety and economic criteria. While further outputs are expected from this project, two assessments of the ‘realisable’ CO2 storage potential in Japan have been published (Akimoto et al., 2002; Li et al., 2005). The principal findings of these various assessments are summarised below (Section 1.2.1.1). At present, RITE is conducting a field demonstration test of CO2 sequestration into an onshore anticlinal aquifer (Nagaoka site). However this is not regarded as the target site in the implementation phase – where the most likely aquifer targets are located offshore to the southeast and northwest of Honshu. Deep unmineable coal seams, many of which extend offshore, are also being considered as future targets for CO2 sequestration; however there remains much work to be done before this becomes a realisable option (Yamazaki et al., 2006).

1.2.1.1 Offshore Storage Potential in Japan

The assessments of offshore storage potential in Japan have considered storage in four reservoir types (Category I-IV, after Tanaka et al., 1995 and Li et al., 2005), including both supercritical based storage in systems with structural traps (oil and gas fields and aquifers containing anticlinal structures) and dissolution based storage in systems without structural traps (monoclinal aquifers). Li et al. (2005) also graded the aquifers according to storage capacity and distance from an emissions source to identify the optimal ‘Rank 1’ sites (in economic terms) for near future development. For Rank 1 status, the storage site must be located within a reasonable distance of a stationary CO2 source equivalent to or greater than the emissions from a medium-scale power plant (~2-2.5 MtCO2/yr) and the technical capacity must be greater than 50 Mt CO2 (20-25 years of storage). The ‘Rank 1’ grading criteria for supercritical based storage requires an emission source within 50km, while that for dissolution based storage requires an emission source within 0km (within or on the aquifer boundary). This allows the lower transport costs to offset the higher injection costs associated with this type of storage (CO2 not in supercritical phase). The location and capacity of these storage sites are summarised below and in Figure 1.7.

Tanaka et al. (1995) considered 13 sites, of which 1 is located offshore. However, these oil and gas fields are still active and are not expected to become CO2 storage sites in the near future (Tanaka et al., 1995; Li et al., 2005). Once depleted, EOR may be considered, or they may be used for natural gas storage, a likely option as Japan imports much of its fossil fuel (Tanaka et al., 1995; Li et al., 2005).

Tanaka et al. (1995) identified 29 Category II sites, 16 on land and 13 offshore, with a potential offshore storage capacity of ~1.4 GtCO2. The offshore Category II sites perhaps represent the most secure storage option. Indeed this is the only category to be considered by Akimoto et al. (2002), where their conservative site selection criteria required offshore aquifers with known structural traps. The offshore area was divided into 19 regions, of which 10 were excluded due to a lack of reliable data. The remaining 9 regions included the 13 known Category II aquifers (see Figure 1.7a). An optimisation model was then applied to match emission sources with the offshore aquifer traps. The model results indicated that geological sequestration at these sites would be an economically viable greenhouse gas mitigation option for Japan (Akimoto et al., 2002). However, it should be noted that for a 0.5%/yr emissions reduction scenario, the total storage capacity of these aquifers would be reached within ~50 years.

Only 2 of the 13 offshore sites meet the ‘Rank 1’ criteria of Li et al. (2005). Although 5 other sites have a capacity in excess of 50 MtCO2, these were rejected on the basis of distance from an emissions source (>100km) and the cost of laying pipeline offshore.

Category III: Aquifers in monoclinal structures on land (dissolution based storage)

This category is included here as one ‘Rank 1’ site (III-9) extends offshore into the Bay of Tokyo, thus possible leakage at this site could occur subsea. The storage capacity of this site is estimated to be 12,351 MtCO2 (Li et al., 2005).

Tanaka et al. (1995) identified 15 Category IV sites within the sedimentary basins surrounding Japan with a potential storage capacity of 72 GtCO2. Li et al. (2005) present a revised assessment based on higher resolution mapping of the area, identifying 28 sites with a potential storage capacity of 102.2 GtCO2. Four of these sites are graded as ‘Rank 1’, with a storage capacity of 23.8 GtCO2, and a further eight sites are graded as ‘Rank 2’ (capacity in excess of 50 MtCO2 and within 50km of an emission source).

Given the high capacity of Category IV sites, dissolution-based storage could become the primary sequestration method in Japan (Li et al., 2005). However, compared with supercritical storage, dissolution-based storage has not been well studied in either the laboratory and in the field. Therefore further research is required to decrease knowledge gaps between theory, simulation, and practical implementations.

The likely regions where geological storage of CO2 will occur beneath Japanese waters are summarised in Figure 1.7. Panel (a) shows the Category II sites and panel (b) shows the Category III and IV aquifers. The Rank 1 sites are those most likely to be developed in the near future, where the most promising aquifer targets are located offshore to the southeast and northwest of Honshu. Given current experience in geological sequestration it also seems likely that the Category II sites (northwest of Honshu) would be developed in preference to Category IV. As Japan is a tectonically active province, the geomechanical properties of these target aquifers will require detailed examination to assess site security, in particular the likelihood of leakage up faults or reactivation during injection due to increased reservoir pressures (Bradshaw & Dance, 2005).

With no development plans yet announced the amount of CO2 to be sequestered in Japan is difficult to assess. The modelling work of Akimoto et al. (2002) indicates a mean sequestration rate of 6.6–35 MtCO2/yr from 2010-2050 would be required to achieve an emissions reduction of 0.5%/yr based on different future economic and population scenarios. The work of Li et al. (2005) indicates a supply potential for Category II Rank 1 sites of 7.4 MtCO2/yr (within a 50km radius), and 49.7 MtCO2/yr for Category IV Rank 1 sites (within 0km). These numbers suggest a sequestration rate on the order of ~7 MtCO2/yr could be achieved in the near future, increasing to ~35-50 MtCO2/yr if dissolution based storage is utilised. Nevertheless, given the concerns regarding the implementation of CO2 storage in tectonically active areas, it seems likely that CO2 storage in Japan will fall toward the lower limit of these ranges.

1.2.2 South East Asia

Following the methodology described above (Section 1.1.4), 30 sedimentary basins in East and South East Asian APEC economies have been selected as primary targets for CO2 geological sequestration based on their proximity to major CO2 sources (both emission cluster analysis and high purity CO2 sources, Bradshaw et al., 2004a). Of these target sites, 7 are located offshore, and a further 12 have an offshore and onshore component (see Figure 1.8). It has been suggested that 13 of these basins should be excluded from near future considerations due to poor accessibility and/or lack of infrastructure (Bachu, 2005). However, this region has numerous offshore gas fields that are naturally rich in CO2 (Imbus et al., 1998; JAPEX, 2003), which may provide good targets for early implementation of CCS. Figure 1.8 shows the location of the sedimentary basins that are considered primary targets, those that have been excluded on the basis of poor accessibility/infrastructure, and those that may become targets if CO2 point sources associated with the future development of natural gas fields are included. The Natuna East sedimentary basin has been included in the latter category here. This basin did not feature in the list of primary targets – yet it as at present the only location in South East Asia where a CCS project is planned, albeit with an uncertain future, and this site is discussed further below.

Figure 1.8: Target sedimentary basins for potential CO2 Storage in East and South East Asia (modified from Bradshaw et al., 2004a).

1.2.2.1 Natuna D-Alpha

Natuna D-Alpha is an offshore gas field located in Indonesia’s East Natuna Sea approximately 1,100km north of the Indonesian capital Jakarta and 225 km northeast of Natuna Island. The Natuna D-Alpha block contains ~6.3 x1012 m3 of gas (222 x1012 cubic feet). However the fuel deposit is extremely impure, with a CO2 content of around ~70% by volume (Herzog et al., 1997). Allowing for separation of the CO2, Exxon Mobil has estimated that the recoverable natural gas reserves are ~1.3 x1012 m3 (46 x1012 cubic feet), accounting for about 25% of Indonesia’s total gas reserves.

At present the status of this gas field is uncertain. Nominally, Exxon Mobil owns a 76 % stake, while the Indonesian state-run oil company Pertamina holds 24%. However, in late 2006 the Indonesian government terminated ExxonMobil’s contract to develop the gas block. This appears to have been due to slow movement on the development of the block. At present, Indonesia and ExxonMobil are negotiating a new contract. It seems likely that a new agreement will be reached, with Exxon Mobil Indonesia Inc. stating that the company is progressing with a four-year plan to deliver natural gas from the Natuna D-Alpha block to foreign buyers by 2014.

Furthermore, it is clear that the Indonesian government is keen to see gas production from this area, thus it is a question of when, rather than whether, this field will be developed.

Current plans for the development of the Natuna D-Alpha field include capture of 90% of the CO2 and injection into two neighbouring deep saline reservoirs ~900 m beneath the bed of the Natuna Sea (Chargin & Socolow, 1997; RCEP, 2000). The decision to employ CCS at this project is in part related to the volume of CO2 that will be produced, where direct venting of the CO2 to the atmosphere would create a massive point source equal to ~0.5% of the current global CO2 emissions from fossil fuels (Chargin & Socolow, 1997). The danger to the local area from such a release (in addition to likely associated political difficulties and economic factors such as possible future taxation on emissions) drove the decision to employ CCS. The large quantities of CO2 to be separated from the gas would be pumped back into the ocean floor using dedicated deep-sea platforms. The project calls for the construction of at least 18 offshore platforms, comprising six for drilling, six for treating and four for injection work. Operations would take place where the water is at least 145 m deep.

Output and injection rates are as yet essentially unknown, although they are likely to be very high. Pertamina has been quoted as projecting an initial output of 5 Mt LNG, which could be increased later to 15 Mt. Other sources suggest a yield as high as 22.2 Mt LNG each year, or around 30% of the world’s output. Thus if the project goes ahead, at full production around 100 MtCO2 would be disposed of annually into a sub-sea bed aquifer (Table 1.3; Chargin & Socolow, 1997; Hanisch, 1998). This is equivalent to 100 ‘Sleipners’, and no other currently announced project would rival this in scale.

Table 1.3: Potential CO2 Sequestration Rates at Natuna D-Alpha (calculated based on projected LPG production rates and assumes the gas feed stream is a binary mixture composed of 30% CH4 and 70% CO2, with capture and storage of 90% of the CO2).

Extraction

LPG Mt/yr

CO2 Extracted

CO2 Stored (90%)

Mt/yr

Mt/yr

Mt/yr

t/day

Initial Rate

5.0

32.1

28.9

79,110

Future Rate

15.0

96.3

86.6

237,329

Maximum Rate

22.2

142.5

128.2

351,247

Mt

Mt

Mt

Total Reserve

929

5963

5367

1.2.3 Oceania (Australia)

As with Japan, Australia is one of the world leaders in the field of CCS, with active research, a roadmap for CCS implementation and pilot studies underway. This program is lead by The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), a collaborative research organisation focused on CO2 capture and geological storage. A detailed regional assessment of storage capacity, CO2 sources, and source to sink matching have been performed, and details are readily available and clearly presented (see for example Bradshaw et al., 2002, 2004b, and the CO2CRC website www.co2crc.com.au).

Source to sink matching and a ranking exercise have also been performed in order to identify those ESSCIs that appear to be the most viable, based on geotechnical, environmental and economic risk factors (Bradshaw et al., 2004b and references therein). This assessment explicitly included potential future LNG sources of CO2 from unproduced gas fields with naturally high CO2 contents located on the North Western Shelf (NWS), the Gorgon, Scott Reef and Evans Shoal fields (see Figure 1.9). Including only the CO2 emissions nodes with large emission volumes, within 300km of a technically viable ESSCI and with low storage costs indicates that Australia has the potential to realistically store between 100 and 115 MtCO2, equivalent to ~25% of its annual total net CO2 emissions. Within this, the unproduced gas fields of the NWS were identified as prime targets for future CCS operations. These fields are likely to be developed in the near future, where if the separated CO2 were simply released to the atmosphere, the production of natural gas could contribute around 4% of Australia’s current CO2 emissions. However, Gorgon & Scott Reef lie within 100km of a technically viable offshore ESSCI, while Evans Shoal lies within 300km, thus providing the ability to sequester the CO2 sub-seafloor with relatively low transport costs (Bradshaw et al., 2002, 2004b). Furthermore, the development of these fields would shift the balance in energy production, with a higher proportion of Australia’s energy requirements being supplied from gas rather than coal. Thus if CCS were implemented at the production stage, this would result in a true decrease in Australia’s CO2 emissions. Plans for the development of the Gorgon field are already at an advanced stage and include CCS as an integral part of the project. This project is discussed in more detail below.

Figure 1.9: Location of potentially viable Environmentally Sustainable Sites for CO2Injection (ESSCIs) in relation to stationary emission nodes and unproduced high CO2 gas fields (image provided by CO2CRC, copyright retained by CO2CRC). The three unproduced gas fields located on the North Western Shelf are (from southwest to northeast) Gorgon, Scott Reef and Evans Shoal.

1.2.3.1 The Gorgon Project

The Gorgon Project plans to develop the Greater Gorgon gas fields, located between 130km and 200km off the north-west coast of Western Australia. This project is being pursued by the Australian subsidiaries of three major international oil companies (the Joint Venturers), Chevron (operator of the project holding a 50% interest), ExxonMobil (25%) and Shell (25%). The project proposal includes greenhouse gas management via injection of carbon dioxide into the Dupuy formation (a saline aquifer) beneath Barrow Island (Oen, 2003). There appear to be multiple driving forces for the implementation of CCS within this project. Firstly, the CO2 has to be removed from the gas stream prior to processing (liquefaction) and marketing. Secondly, in the absence of a CO2 emission abatement or mitigation strategy, the Australian EPA made a strong recommendation against further development of the Barrow Island nature reserve site (see current status below). Thirdly, as major international energy companies the Joint Venturers have a vested interest in the development and demonstration of CCS technology, where incentives provided by the Australian Government through the Low Emissions Technology Demonstration Fund (LETDF), encourages industry investment in this region, offering $1 for every $2 spent by industry for projects that demonstrate new low greenhouse emissions technology. Chevron was recently awarded a $AU 60m grant to demonstrate CO2 capture from the Gorgon gas field development and sequestration in a saline aquifer under Barrow Island.

The gas fields of the Greater Gorgon area (comprising the Gorgon area and Jansz field among others) represent Australia’s largest-known undeveloped gas resource, containing ~1.1 x1012 m3 of natural gas (40 x1012 cubic feet). While the CO2 content of the Jansz field is low (0.25% by volume), gas in the Gorgon area has a high CO2 content ranging from 10-15% by volume, with a typical composition of 14-15% CO2 and 2-3% N2. The technically proven and certified recoverable gas resource of the Gorgon area is 0.37 x1012 m3 (12.9 x1012 cubic feet), corresponding to a reservoir CO2 volume of approximately 65 x109 m3, or ~125 Mt CO2. The CO2 (and other trace contaminants such as H2S) will be removed from the raw gas feed stream as part of the gas pre-treatment before processing, where the recovered CO2 will be injected back into the subsurface below Barrow Island. The maximum anticipated rate of CO2 removal is 3.4 Mt/yr, with an average rate of 3.1 Mt/yr over the life of the project. Under routine operations, it is expected that all CO2 removed from the incoming gas stream would be injected into the subsurface. However, venting of reservoir CO2 may be required during commissioning, maintenance periods, unplanned downtime and in the event of reservoir or injection well constraints. The long term goal is to achieve injection of 95% of the reservoir gas (Chevron, 2005). However, the reference case adopted by the Joint Venturers is based on a worst-case scenario that assumes venting of 20% of reservoir CO2 to the atmosphere, providing an allowance of ~5% for maintenance and compressor down time plus ~15% assuming one of the seven planned injection wells is offline. Thus CO2 injection at this site is expected to range between 2.7-3.4 MtCO2/yr.

Injection Site

Extensive investigations of the feasibility of CO2 injection at the Gorgon project have been carried out, both by the Joint Venturers (Chevron 2005) and via an independent report (Curtin University of Technology, 2004) commissioned by the Australian Department of Industry and Resources (DoIR). This has included assessment of potential CO2 injection sites, subsurface geology and stratigraphy, injectivity, storage capacity and likely CO2 behaviour and movement in the subsurface.

The intention is to inject reservoir CO2 into the Dupuy Formation, approximately 2300m below Barrow Island, with the CO2 injection facility located on the central eastern coast of Barrow Island. This site was selected to maximise the migration distance from major geological faults and to limit disturbance to areas around the proposed gas processing plant. The injection wells are planned to be directionally drilled from two surface locations, with a total of 7 (6-8) injection wells. It is likely that a monitoring well (or wells) will be drilled from each cluster of injection wells to provide a sample point within the area of injection

The Dupuy Formation appears to have adequate capacity to contain the ~125 Mt CO2 that will be potentially available for injection over the life of the project, where the Basal Barrow Group seal which overlies the Dupuy Formation should be adequate to contain the injected CO2 for thousands of years (Curtin University of Technology, 2004).

Although the injection site is located on land, the migration of CO2 within the Dupuy formation will result in CO2 storage beneath both Barrow Island and the adjacent shallow waters of the coast, i.e. the intended storage site is both sub-terrestrial and sub-seafloor. The Joint Venturers also note that the Greater Gorgon gas fields themselves would provide significant additional CO2 storage capacity once the hydrocarbon reservoirs are depleted. Thus if carbon storage in sub-sea geologic formations proves successful, this region may see significant further development as a storage site in the future.

Project Status

The Gorgon Project is now nearing the end of a lengthy and thorough environmental approval process. The associated documents are publicly available and provide detailed information on the project. This includes the independent report commissioned by the DoIR (Curtin University of Technology, 2004) in addition to the following documents prepared by the Joint Venturers:

The draft Environmental Impact Statement/Environmental Review and Management Program (EIS/ERMP) document. This meets the requirements of environmental impact assessment processes under the Commonwealth Environment Protection and Biodiversity Conservation Act 1999 and the Western Australian Environmental Protection Act 1986.

An Additional Information Package containing supporting technical information that became available following the release of the Draft EIS/ERMP.

The Final Environmental Impact Statement/Response to Submissions on the Environmental Review and Management Program.

In June 2006, the Western Australia Environmental Protection Authority (WA EPA) published an advisory bulletin (Bulletin 1221) recommending against the Gorgon project’s EIS/ERMP. This was largely due to negative impacts on the Barrow Island Nature Reserve (Barrow Island is a Class A internationally significant nature reserve recognised for its very high conservation values, where the waters around Barrow Island are also recognised for their conservation values, with parts included in marine conservation reserves and a marine park). The EPA also noted that the opportunity to inject reservoir CO2 was a key argument for the use of Barrow Island, and made a clear statement that should the project proceed the EPA considers it essential that injection or equivalent greenhouse gas mitigation action occurs.

The Western Australia Environment Minister has since upheld the Gorgon Joint Venturers appeal against the EPAs advisory bulletin. However, in response to the recommendation of the EPA, geological sequestration of CO2 has now been made a condition of the development.

Prior to this decision, the Gorgon Joint Venturers were publicly committed to injection of 80% of the reservoir CO2 unless it proved “technically infeasible or cost prohibitive”. The successful injection of CO2 is now an integral part of the Gorgon Project, without which development of the gas field cannot proceed as planned. A test well was drilled into the Dupuy Formation in early 2006 and comprehensive tests and analysis to assess the ability to inject the CO2 at Barrow Island are now underway. Assuming that test results are positive and CO2 injection is possible, the final decision on the Gorgon Project is in the hands of the federal Environment Minister. Given the Australian governments support for CCS, including funding awarded to Chevron via the LETDF specifically for the purposes of demonstrating CCS at the Gorgon site, it seems likely that this project will proceed as planned with production commencing in 2008-2010.

1.2.4 Western Europe (North Sea, Barents Sea & Mediterranean Sea)

Western Europe is a world leader in the field of offshore CCS, where the only two currently operating sub-seafloor CO2 storage projects in the world are located in the North Sea. The dynamic European CCS research community includes national programs, industry led projects (in particular by Statoil, a true world leader in CCS technology) and academic-industrial collaborations, which are supported at the regional level through the European Commission Framework Programs (see European Communities (2004) for an overview of programs funded via FP5 (1999-2002) and FP6 (2002-2006), calls for FP7 opened in December 2006). In light of the wealth of both available storage opportunities, and available information regarding European CCS activities, this subject matter could form the basis of an individual report. Here the focus has therefore been restricted to specific current and planned future projects.

Two major projects have assessed European CO2 storage capacity (including depleted oil and gas fields and deep saline aquifers), JOULE II (1996) and GESTCO (2003). These studies examined specific case studies, and do not represent a comprehensive coverage of all storage potential in Europe. Nevertheless, estimates of the regional storage potential clearly demonstrate that the vast majority of Western Europe’s CO2 storage capacity occurs in offshore formations; with the majority of offshore storage sites occurring within the UK and Norwegian sectors of the North Sea (see Table 1.2; Holloway, 1996; Bøe et al., 2002; IEA-GHG 2004; Wildenborg et al., 2005). This region represents an ideal candidate for sub-seafloor storage of CO2 due to a good understanding of its geology (proven storage capabilities over geological time) and proximity to stationary CO2 sources. Furthermore, many of the North Sea oil and gas fields are now nearing depletion. While this provides opportunities for enhanced oil and gas recovery (EOR and EGR), it also creates a finite time window within which existing infrastructure can be adopted and converted to accommodate CO2 injection (rather than removed, as is required on decommissioning). Thus rapid development of the North Sea as a major CO2 storage site might be expected. Indeed, in late 2005, government and industry representatives from Denmark, Germany, The Netherlands, Norway and the UK reached an agreement to promote large-scale CCS as an effective way to tackle global climate change and signed a joint declaration on geological storage beneath the North Sea. This declaration agreed to set up a ‘North Sea Basin Task Force’ to develop common principles to regulate CO2 storage and to explore possible areas of co-operation.

Current offshore CCS schemes in Europe include the first example of a geological CO2 storage facility (the Sleipner project) and a pilot scale project investigating the potential for CO2 storage combined with EGR (the K12-B project), with numerous other projects either under development or under consideration. Of these, three sites fall under the umbrella of the European CASTOR (CO2, from capture to storage) project, the K12-B project in the North Sea, the Snøhvit project in the Barents Sea, and the Casablanca project in the Mediterranean Sea. One of the principal objectives of the CASTOR project is to develop and apply a methodology for the selection and the secure management of storage sites by improving assessment methods, defining acceptance criteria, and developing a strategy for safety-focussed, cost-effective site monitoring. As such, these sites have been chosen to reflect a broad range of reservoir characteristics. Source-sink matching and cost benefit analysis are also highly developed in this region, as is illustrated by the concept of the CO2 value chain. For example, near-future European projects will extend the role of CCS to include schemes that link the generation of CO2 at large power stations (fueled by North Sea hydrocarbon reserves) to the application of EOR within the North Sea, and strive to create zero emissions systems (see for example the Tjeldbergodden/Heidrun/Draugen and Miller/Peterhead Projects). Various European sub-seafloor CO2 storage projects are described briefly below and summarised in Figure 1.10 and Table 1.4.

Figure 1.10: CCS Operations in the North, Norwegian and Barents Seas.

Table 1.4Current & future offshore CO2 storage projects.

Project Status

Location

Storage Rate MtCO2/yr

Project Start

Current Projects

Sleipner

Norway

1.00

1996

K1-2B

Netherlands

Initial

0.02

2004

Increasing to

0.31 - 0.48

2007-2008

Snøhvit

Norway

0.75

2007

Future Planned/Proposed

Gorgon

Australia

2.70 - 3.40

2008-2010

Miller/Peterhead

UK

1.80

2009

Teeside

UK

4.00

2011

Tjeldbergodden/Heidrun/Draugen

Norway

2.50

2012

Mongstad

Norway

Initial

0.10

2010

Increasing to

1.30

2014

Kårstø

Norway

1.00 - 1.20

2011-2012

Uncertain Future

Natuna

Indonesia

28.9 - 86.6

post 2014?

Japan

Japan

~7

post 2010?

Casablanca

Spain

0.50

?

1.2.4.1 The Sleipner Project, North Sea

Initial practical experience in the geological storage of CO2 beneath the seafloor is being obtained in the Norwegian sector of the central North Sea area, where CO2 from the Sleipner West gas field (owned and operated by Statoil) is extracted, captured, and injected back into a deep saline aquifer located at a depth of ~1000m.

The Sleipner West natural gas field has a naturally high CO2 content of ~4.0-9.5% by volume. For natural gas to be fed directly into pipelines for sale in Europe, the CO2 content must be less than 2.5% by volume, thus development of this field required removal of CO2 from the produced gas by necessity. Furthermore, at the time of development (1990), it was known that the Norwegian government would shortly be introducing significant CO2 emissions taxation on the offshore petroleum industry (~$ 40/t CO2, introduced in 1991). In response to these factors, a team of technical experts came up with the then unprecedented idea of capturing the CO2 offshore and injecting it into a saline aquifer beneath the Sleipner installations. Statoil proceeded with this pioneering project (for both environmental and financial benefit) and since project start up in 1996 around ~1MtCO2/yr has been injected into the Utsira aquifer.

The Sleipner West field is produced through two installations; the Sleipner B (SLB) wellhead platform and the Sleipner T (SLT) gas treatment facility. The carbon dioxide removal plant installed on the SLT platform is the first employed in the North Sea and was the largest offshore facility of its kind (a Total patented amine separation process) at the time of commissioning. The CO2 extracted from the natural gas feed stream is injected into the water-bearing Upper Miocene Utsira Formation, located at a depth of 1,000 metres above the Sleipner West reservoir, and overlain by an 80 m thick Nordland Group shale cap rock. The Utsira Formation forms an elongated sand-body about 450 km long and 90 km wide, with a maximum thickness of 250-330 m. According to Statoil, the estimated capacity of this aquifer is several GtCO2.

In order to learn as much as possible from this first endeavor in the realm of geological storage a collaborative research project, the Saline Aquifer CO2 Storage Project (SACS) was established in 1998 to examine and monitor the behaviour of injected CO2 within the Utsira Formation. The SACS project finished in 2003, and this work is now being continued by the partly EU funded CO2STORE project.

1.2.4.2 K12-B – The ORC Project, North Sea

In the Netherlands a pilot scale CO2 injection program is being carried out by Gaz de France Production Netherland B.V. (GPN) at the K12-B offshore gas field in the Dutch sector of the North Sea (van der Meer et al., 2005).

The K12-B platform, located 150 km NW of Amsterdam, is the test facility for GPN’s ORC project (Offshore Reinjection of CO2). This project forms part of the Dutch CRUST program (CO2 Re-use through Underground STorage) and the European CASTOR program, and was jointly funded by GPN (10%) and The Ministry of Economic Affairs of the Netherlands (90%). The aims of the ORC project were to assess (i) the feasibility of CO2 storage in a depleted gas reservoir and (ii) the possibility of using CO2 injection for Enhanced Gas Recovery (EGR). If the ORC project is deemed successful CO2 could also be injected into other fields in this area for both storage and EGR purposes.

K12-B was selected as a potential CO2 injection test site as the gas field was nearing depletion and the platform was already equipped with a CO2 removal plant due to the high CO2 content of the reservoir gas (~13%). A feasibility study conducted in 2002-2003 concluded that excellent facilities were available for a demonstration project, that the reservoir has good characteristics for CO2 re-injection and storage, and that there were no significant legal or social barriers to the project (van der Meer, 2004). Pilot scale CO2 injection was initiated in May 2004. This is the first site in the world where CO2 has been injected into the same reservoir from which it originated, the Rotliegend sandstone located at a depth of ~3800m (Upper Slochteren Member, Permian age).

The pilot phase involved two injection tests. Test 1 (initiated in May 2004) involved CO2 injection into a single-well depleted reservoir compartment (K12-B8) and demonstrated reasonable CO2injectivity despite the low permeability of the reservoir, where the reservoir response and behavior of the injected CO2 were within the expected range (Van der Meer, 2005). Test 2 (initiated in March 2005) involved CO2 injection into a producing compartment of the reservoir to evaluate the potential for EGR in K12-B (Van der Meer 2006). This test involved three wells, a CO2 injection well (K12-B6) and two producing gas wells (K12-B1 and K12-B5). Tracer experiments were also carried out to enable monitoring of any breakthrough of injected CO2 into the methane production wells. Results from the 2005 injection period demonstrated that CO2 breakthrough could be modelled accurately, where simulation results indicate that CO2 increase in the gas-production wells would be slow and gradual, and the volumetric consequences of CO2 breakthrough in K12-B1 were undetectable within the test period. However, at the end of 2005 there was no clear evidence of measurable improvement in the gas-production performance of the tested compartment and it was concluded that this test phase should be continued into 2006 to increase the EGR potential of CO2 injection (Van der Meer, 2006). Results from the 2006 injection program should be available in the near future.

During the pilot test phase CO2 injection at this site has been restricted to 20 kt CO2/yr, with an injection rate of ~50 to 60 t/day. However, with the successful completion of the test injection, the K12-B project is expected to enter into commercial phase operation in the near future, with an injection potential of 310 to 475 kt CO2/yr and a total estimated reservoir size of 8Mt CO2 or ~17-25 years of storage (van der Meer 2006).

1.2.4.3 The Snøhvit Project, Barents Sea

Statoil and its partners are involved in a second offshore CO2 storage venture, the Snøhvit project, which is due to commence in June 2007. This project (part of the European CASTOR project) will be the first oil and gas development in the environmentally sensitive Barents Sea, the first LNG gas-field development in Europe, and the first LNG production site where the captured CO2 will be stored. The Snøhvit Field, located in the Barents Sea, contains natural gas with a CO2 content of 5-8% by volume. A full subsea solution is being used for the development of this site, with all production equipment residing at water depths of 250 to 345 m. The produced gas will be fed to an onshore reception terminal on Melkøya. Here the CO2 will be removed from the natural gas feed stream (as at Sleipner, the CO2 will be captured by amine absorption), dewatered, compressed, sent back offshore via a dedicated pipeline, and injected into the Tubåen Formation. This storage aquifer is located beneath the gas-bearing strata at a depth of ~2,600 m and is capped by 75-125 m of thick impermeable shale. It is expected that ~0.75 MtCO2 will be reinjected per annum.

1.2.4.4 Tjeldbergodden/Heidrun/Draugen, Norwegian Sea

This joint venture between Shell and Statoil plans to establish a complete CO2 value chain in Norway. The proposed project involves a new 850MW gas-fired power station at the Tjeldbergodden industrial complex facility in Mid Norway, which currently comprises a gas receiving terminal, methanol plant, an air separation facility and a gas liquefaction unit. Natural gas will be piped to the power station via the existing Haltenpipe pipeline. Around 85% of post-combustion CO2 emissions from the power station will be captured, in addition to capture of CO2 from the methanol production facility. The CO2 will be dewatered, compressed, and transported offshore via a pipeline for CO2-EOR based storage, first at the Shell operated Draugen field and later at the Statoil-operated Heidrun field. Currently Shell and Statoil are undertaking a feasibility study and will decide upon a final concept if the project is deemed to be commercial. A decision to award the project sanction will be taken at the end of 2008, which could allow project start-up by 2010 and full operation by 2012. If the project proceeds, up to 2.5 MtCO2 (including ~ 0.3 MtCO2/yr from the existing methanol plant) could be injected annually.

1.2.4.5 Miller/Peterhead (BP-DF1), North Sea

The BP Miller/Peterhead Power Station project, referred to as DF1 (decarbonised fuels 1), aims to generate electricity using hydrogen manufactured from North Sea natural gas, where the CO2 created in the gas reforming process is captured and utilised for CO2-EOR at the Miller field. The project, if it goes ahead, will be the first industrial scale decarbonised fuel project in the world and will be able to reduce CO2 emissions from the electricity generation process by around 90%. North Sea gas will be supplied via an existing link from the St. Fergus terminal to a new reformer based at the Peterhead Power Station. The CO2 captured from the gas reforming process will be transported via an existing gas export pipeline to be injected for EOR and long-term geological storage in the Miller field reservoir which lies at a depth of around 3,500 metres. The Miller field was selected as a CO2 storage site as (i) it is uniquely positioned with an existing, dedicated high-grade steel pipeline connected to a suitable power station (ii) the high specification pipeline is able to handle the corrosive properties of a high-CO2 content gas stream (iii) Miller has gas re-injection facilities (iv) CO2 naturally present in the field has been proven to be held in the reservoir on a geological timescale (v) the application of CO2-EOR could increase recoverable oil reserves by around 60 million barrels and extend the life of the field by around 20 years. This development could commence as early as 2009, with a projected CO2 sequestration rate of ~1.8 MtCO2/yr.

1.2.4.6 Other North Sea Projects

Plans have recently been announced for the UK’s first complete clean coal power generation project (Centrica PLC, Progressive Energy Ltd., Coastal Energy Ltd., and Coots Ltd). If progressed, this project would involve the construction of a new 800 MW Integrated Gasification Combined Cycle (IGCC) power station (located in Teesside, UK) combined with CO2 capture, transport via a new pipeline, and storage in the North Sea. The project has a projected start date of 2011, and no further details are as yet available. However, a CO2 storage rate of ~4 MtCO2/yr can be estimated based on the expected annual energy output (6 TWh/yr) and applying the representative figures provided by the IPCC for emissions reductions associated with new IGCC power plants combined with CSS (86% - equivalent to capture of ~0.665 kgCO2/kWh; IPCC, 2005).

In Norway, all new-build gas fired power stations are now expected to be ‘carbon recovery ready’. For example, the recently approved combined heat and power (CHP) plant at Kårstø (Naturkraft; ~3.5 TWh/yr) is being built to allow retrofitting of carbon capture systems. At full production this plant will have emissions of ~1.0-1.2 MtCO2/yr, where CCS is expected to implemented post 2011-2012. At a similar new CHP plant at Mongstad (Statoil; ~2.2 TWh/yr) carbon capture systems are to be built simultaneously with the power plant, where the emissions permit from the Norwegian government requires capture of at least 0.1 MtCO2/yr to start at the same time as power production, with full emissions capture (1.3 MtCO2/yr) in operation by 2014. The storage plans for these projects have not yet been announced.

1.2.4.7 The Casablanca Project, Mediterranean Sea

The Casablanca oil field is operated by Repsol-YPF and is situated off the coast of northeastern Spain in the Mediterranean Sea, approximately 43 km from Tarragona. This carbonate hosted oil field, located at a depth of ~2500m below the seafloor, and is nearing the end of its productive life, where the economic limit of the field will be reached in the next few years. Repsol-YPF is therefore considering using this field for storage of approximately 0.5 MtCO2/yr, which is to be captured at the company’s Tarragona refinery (~20% of the refinery’s annual production). At present, this is the only project planned for the Mediterranean Sea.

Evaluation of the Casablanca oil fields’ suitability as a CO2 storage site is being carried out as part of the CASTOR project (Mignot et al., 2006). This field case has been divided into several steps, including a geological study, reservoir modeling, forecast of CO2 injection, well integrity, and long term behavior of CO2 in the subsurface (Mignot et al., 2006). To date, early results have been reported from the first three steps of the study (Mignot et al., 2006). There is not (as yet) a projected start date for CO2 injection as a full evaluation of the ability of this field to be safely used as a geological storage site awaits the results of the full study (Mignot et al., 2006),.

1.2.4.8 The Rate of Sub-Seafloor Storage of CO2 in Western Europe

The injection of CO2 into sub-seafloor geologic reservoirs in Western Europe is currently occurring at a rate of ~1 MtCO2/yr (see Table 1.4). If all current and future planned projects proceed according to projected timescale, this will increase to 2.1-2.2 MtCO2/yr by the end or 2007, 4.0-4.1 MtCO2/yr by 2010, and 12.7-13.0 MtCO2/yr by 2015 (13.2-13.5 MtCO2/yr if Casablanca is included).

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